The Sonoma County District Attorney’s office filed 33 criminal charges Tuesday against Pacific Gas and Electric in connection with the Kincade Fire, which tore through Northern California wine country in October 2019.
Six firefighters were injured in the blaze; no one was killed. Authorities ordered mass evacuations as the wind-stoked fire burned 78,000 acres of hillsides and vineyards and destroyed 374 structures, including 174 homes and a historic winery established in the 1800s. (See PG&E Stock Plummets amid Wildfires, Shutoffs.)
The fire started near The Geysers, a sprawling geothermal field about 70 miles north of San Francisco, when a piece of a PG&E transmission line broke loose and arced against its tower, sending a shower of sparks onto dry vegetation below, the California Department of Forestry and Fire Protection (Cal Fire) concluded.
PG&E accepted those findings but denied the criminal allegations Tuesday.
“In the spirit of working to do what’s right for the victims, we will accept Cal Fire’s finding that a PG&E transmission line caused the fire, even though we have not had access to the agency’s report or the evidence it gathered,” the utility said in a statement Tuesday. “However, we do not believe there was any crime here.”
Cal Fire concluded its investigation and referred the matter to the prosecutor’s office in July 2020. The district attorney’s office said it conducted its own detailed investigation and determined criminal charges were warranted.
“I went with others from my team, along with Cal Fire, to the location in The Geysers where we believe the fire began as soon as it was safe to do so,” Sonoma County District Attorney Jill Ravitch said in a statement. “Since that time, we have been working with Cal Fire and independent experts to determine the cause of and responsibility for the Kincade fire. I believe this criminal complaint reflects our findings.”
In a 20-page complaint, Ravitch’s office charged PG&E with five felonies and 28 misdemeanors. The felony charges include “recklessly causing a fire with great bodily injury” to the firefighters, named as John Does Nos. 1-6. Another felony charge accuses PG&E of emitting harmful contaminants such as wildfire smoke and ash into the air, harming a child named as “Minor Victim No. 1.”
“The Kincade Fire caused substantial emissions of air contaminates throughout the county, threatening the health and safety of residents and their property,” the district attorney’s office said in a news release. “Exposure to wildfire smoke has the potential to cause serious health conditions, including increased risk of stroke, and serious respiratory conditions, such as worsening asthma in children.”
The complaint marks the third time in the past decade that PG&E, the state’s largest utility, has been charged with felonies.
The Kincade Fire tore through Sonoma County in October 2019. | Cal Fire
The utility remains under criminal probation for six felony convictions stemming from the San Bruno gas pipeline explosion, which killed eight residents and destroyed part of a suburban San Francisco neighborhood in September 2010.
PG&E pleaded guilty last June to 84 counts of involuntary manslaughter in the November 2018 Camp Fire, the state’s deadliest and most destructive wildland blaze. (See PG&E Pleads Guilty to 84 Homicides and Arson.)
Cal Fire found that PG&E equipment ignited the Camp Fire along with 21 of the major wine country wildfires in October 2017. It also found a PG&E line had sparked last year’s Zogg Fire in Shasta County, which killed four people.
In a February hearing on PG&E’s role in the Zogg Fire, federal Judge William Alsup, who oversees PG&E’s probation from the San Bruno disaster, said the utility’s failure to maintain its lines made it a “terror” to California residents.
New PG&E CEO Patti Poppe insisted Tuesday that PG&E will change.
“I came to PG&E in January to ensure that we care for all those who were harmed and that we make it safe again in California,” Poppe said in a statement. “We will work around the clock until that is true for all people we are privileged to serve.”
FERC last week sent CAISO’s first systemwide reliability-must-run (RMR) agreement to settlement proceedings after the ISO raised questions about the fairness of the contract’s cost structure.
While the commission approved the unexecuted RMR agreement for Midway Sunset Cogeneration Co.’s (MSCC) plant near Bakersfield, Calif., beginning Feb. 1, it declined to rule on the reasonableness of the arrangement without additional details (ER21-998-001).
CAISO designated Midway as RMR in December after determining that it must prevent the 248-MW gas-fired plant from retiring in order to meet systemwide reliability standards after experiencing blackouts in August. (See CAISO Board Fields RA Measures, Big and Small.)
But in negotiating the RMR, MSCC proposed multiple deviations from the cost recovery mechanisms in CAISO’s standard agreement contract, prompting protest from the ISO. The grid operator said Midway incorrectly cast its situation as being unique and took too many liberties with the FERC-approved RMR contract. CAISO also contended that the company had misrepresented the plant’s ability to provide RMR service.
Midway Sunset Cogen Plant | Union of Concerned Scientists
In seeking additional cost recovery, MSCC said the plant’s three turbines must undergo “major maintenance projects” in 2021 if they’re to provide RMR service. It said Turbine C needed the most extensive work because its nitrogen emissions exceed permit limitations when in simple-cycle mode.
The company elected to include “a daily surcharge for transition costs” in its RMR capacity payments starting from its December 2020 RMR designation until the RMR’s effective date on Feb. 1. It also proposed a fast-paced depreciation for the turbine upgrades based on the plant’s 23-month “remaining economic useful life,” reasoning that CAISO will probably renew the facility’s RMR status into 2022.
MSCC said it “negotiated operational provisions with CAISO in good faith, but that its negotiations were complicated due to the need for facility maintenance during the 2021 year.”
CAISO argued that Midway’s proposed daily transition cost surcharge violates FERC’s principle that “cost recovery should not commence until a capital item is placed in service.” It also argued that the company should record its stack repair costs as capital costs rather than transition costs and depreciate the expense over 10 years, rather than two.
Midway also proposed using an alternative to CAISO’s Resource Adequacy Availability Incentive Mechanism performance rule, which penalizes generating units failing to meet performance requirements. The proposal would use the plant’s seasonal ambient derates — not CAISO’s prescribed maximum normal capability (Pmax) — to calculate the agreement’s non-availability charge. The company argued that it did not have a historically established Pmax and its “turbines experience ambient derates relative to Pmax in most months.”
The ISO said MSCC’s bid for adjusted performance rules was “an unjustified departure from CAISO’s method of addressing ambient derates that gas plants may require in hot weather.”
Other Protests
The California Public Utilities Commission, PG&E, San Diego Gas and Electric Co. and SoCal Edison joined CAISO in protesting the agreement.
While they didn’t oppose the facility’s RMR designation, the entities said that hearing and settlement proceedings would “allow time for third-party review to ensure the proposed costs in the RMR agreement are just and reasonable.”
SoCal also questioned Midway’s accelerated depreciation schedule, saying it was “unclear why depreciation would be accelerated over the RMR agreement term since Midway intended that the facility be mothballed.”
The protesters also raised doubts about whether some of the turbine maintenance would have been necessary in order to mothball the plant as originally intended and said that it should be excluded from RMR recovery. Midway also included asset retirement costs in its RMR rates, which isn’t permitted, CAISO said.
The ISO acknowledged the potential need for Midway to make repairs and upgrades to provide reliability service, but said it needed to see “additional documentation” to justify the work.
PG&E contended that extra scrutiny was necessary given that the agreement represents CAISO’s first systemwide — rather than local — RMR designation; it remains unclear what conditions the ISO would look for before an RMR assignment is lifted.
SoCal said CAISO might have improperly used a 20% planning reserve margin requirement in calling for the RMR, instead of its current 15% PRM requirement.
Danly Criticizes RMRs
While Commissioner James Danly agreed with FERC’s decision to allow the RMR contract to proceed with a hearing, he penned a separate statement railing against RMRs, calling them a “short-term fix” and evidence of failed markets.
“Rather than RMRs being the last resort that Commission precedent demands, it appears that the instant RMR agreement with Midway is CAISO’s first resort to address its failure to ensure that it acquires and retains sufficient capacity,” he said.
Danly argued for an investigation into CAISO’s markets and whether they could benefit from pricing reforms to prevent generators from retiring early. He also said the commission’s practice of granting RMR requests without requiring justification for the decision remains flawed.
Maine regulators are moving forward with a formal investigation of Central Maine Power’s distributed generation interconnection practices.
The decision came after a preliminary review of recent interconnection studies did not resolve concerns raised by the Coalition for Community Solar Access and the Maine Renewable Energy Association, Chairman Philip Bartlett said during a Public Utilities Commission meeting Tuesday.
The two nonprofits called for the investigation in February, claiming CMP was jeopardizing as much as 540 MW of clean energy by reneging on costs set out in current interconnection agreements.
“Being able to interconnect projects — and rely on any cost upgrade estimates from CMP — is an important step toward being able to get a project financed, and then ultimately built and reaching commercial operation,” Jeremy Payne, executive director of MREA, told RTO Insider.
Maine regulators are investigating difficulties that planned solar arrays like this 4-MW project in central Maine are having achieving interconnection with the grid. | Revision Solar
The state has seen an overwhelming response to 2019 laws designed to promote renewable energy development, according to CMP spokesperson Catharine Hartnett.
There has been a “dramatic influx of solar development … resulting in 600-plus requests to interconnect over 2,000 MW onto CMP’s distribution network — 300 MW more than our system peak load now — in less than two years,” she told RTO Insider, adding that the influx has “created significant technical challenges for developers and utilities alike.”
While the interest in solar “is great news for achieving Maine’s climate policy objectives,” Hartnett said, “such transformational changes must be managed with careful and timely study and proper execution to ensure the continued safe and reliable service to our customers.”
CMP, she said, is committed to Maine’s clean energy future and will fully cooperate with the commission’s investigation.
Investigation Scope
The investigation will address, among other things, whether CMP’s efforts to identify issues related to potential DG islanding situations was timely and if its response to its findings was appropriate.
Islanding occurs when a DG facility continues to provide power to customers when electricity from the grid stops serving those customers. Without protection, overvoltage on un-faulted phases of the transmission circuit can damage customer and utility equipment, CMP said.
In response to a March 12 commission data request, the utility said that its understanding of possible islanding issues evolved during 2020. After an assessment of its current substation technology, CMP determined that “a significant number” of substations would need upgrades to properly detect overvoltage situations.
The costs for those upgrades are now affecting the system upgrade charges already established in existing interconnection agreements with developers.
In their Feb. 10 letter to the commission, the nonprofits said upgrade charges for the interconnection of a 2-MW solar project, for example, jumped from $239,000 to $12.2 million.
Bartlett said the commission’s investigation will determine whether CMP’s communications with developers about the costs were reasonable and whether the utility should be fined.
“We are pleased the commissioners unanimously agree that the severity of CMP interconnection errors and issues warrant a formal investigation,” Payne said. “In order to ensure these mistakes are not repeated, it is important we find out what happened, why it happened, and be sure there are processes put in place to avoid a repeat occurrence.”
As the COVID-19 pandemic forced office-based employees of Connecticut’s electric, gas and water utilities to primarily remote work last March, it laid bare cybersecurity vulnerabilities from attempting to recreate network connectivity from personal devices and homes using virtual private networks.
While the report notes progress made by Eversource Energy, Avangrid, Connecticut Water and Aquarion Water Co. in 2020, PURA urged them to beef up cybersecurity protocols and test threat-response systems as cyberattacks continue to increase each year in volume as well as speed and sophistication.
PURA said the “massive societal shift” to a work-from-home status allowed for the increasing use of phishing attacks and malware by cyber actors and criminals targeting personal accounts and systems in addition to online meeting platforms.
“Cybersecurity must remain a key objective for Connecticut utility companies as cybercriminals continue to take advantage of the challenges brought forth by the pandemic,” PURA Chairman Marissa Gillett said in a statement.
Gone Phishing
Phishing attempts are still the primary form of cyberattack, according to the report. The deployment of new technologies to identify and exploit vulnerabilities indicates growing activity by sophisticated cyber actors, which are often backed by state sponsors such as Russia, China and Iran. C-suite executives were the target of sophisticated phishing attempts, highlighting the need to prioritize company executives’ training. There was a spike in activity from less sophisticated actors in generic phishing attempts to steal log-in credentials or introduce malware, often in search of “illicit financial gain.”
The report said that robust, frequent phishing testing of employees, as often as monthly, “provides real-world examples” to help them identify phishing attempts. If a regular testing program is not in place at a utility, it is “seriously deficient” and “must be addressed with urgency.”
Third-party Vulnerabilities
The report also added that third-party vendors are an additional area of concern as they often provide external services to utilities such as business email, which can be compromised. In these “squatting attacks,” actors register similar domain names to the utility company and target its vendors.
“Doing business with external vendors makes the utilities depend to an extent on the security of the vendors themselves,” PURA wrote. “This security dependency requires that the utilities invest significant resources to ensure the vendors have adequate security programs to protect the company.”
Learn by Committee
The state runs the Connecticut Cybersecurity Committee, which meets every month. Consisting of state agencies, local governments, federal partners and private companies, it briefs participants on current threats and trends and provides training activities and sharing of “lessons learned” information.
Most of the state’s utilities took part last year in the committee, which shared real-time updates on the SolarWinds Orion hack made public in December. The exploit potentially affected many federal agencies and private companies, but it was particularly notable for utility companies as the product monitors operational systems network traffic. PURA said it was “premature at this time” to discuss detailed responses by the utilities.
FERC and the Department of Energy were also attacked, and the commission in December proposed incentives to encourage public utilities to make cybersecurity investments above and beyond the requirements of NERC’s Critical Infrastructure Protection standards. (See FERC Pushes Cybersecurity Incentives.)
Bills approved in Virginia’s recently concluded 2021 legislative session will tighten vehicle emission standards, promote electric vehicles and streamline permitting for energy storage projects. Lawmakers also created a program for developing renewable energy on brownfields and former coal mines and ordered an inventory of the state’s greenhouse gas emissions.
Much of the legislation signed by Gov. Ralph Northam (D) builds on last year’s landmark Virginia Clean Economy Act, which set a goal of net-zero GHG by 2045 in all sectors. (See Va. 1st Southern State with 100% Clean Energy Target.)
Focus on Vehicle Emissions
Vehicle emissions, the source of almost half of the state’s GHG emissions, were the focus of several bills, including HB 1965, which invokes the federal Clean Air Act’s provision allowing states to adopt California emission standards, which are more rigorous than those imposed by the federal government.
The bill requires the Air Pollution Control Board to implement a low-emissions and zero-emissions vehicle program for motor vehicles with a model year of 2025 and later. According to the Sierra Club, the bill makes Virginia one of 14 states to adopt clean car standards, which require a certain proportion of new vehicle sales be zero-emission or plug-in electric vehicles.
“This bill will ensure that Virginians don’t have to travel out of the state to purchase electric vehicles,” said Rebekah Whilden of the Sierra Club’s Clean Transportation for All campaign.
The powerful Virginia Auto Dealers Association praised the bill when it was winding its way through the legislature. “VADA and its dealer members are fully supportive of efforts to increase electric vehicles sales, and we must move forward in a smart and effective manner to set up Virginia for success,” CEO Don Hall said in a memo to lawmakers.
A second bill requires the State Corporation Commission to submit a report to the General Assembly by May 1, 2022, recommending proposals on how electric utility programs can speed up adoption of EVs (HB 2282).
The law directs the SCC to identify areas where utility or other public investment can complement private efforts to deploy charging infrastructure, with an emphasis on low-income, minority and rural communities. The report must determine whether transportation electrification can reduce customer rates, assist in grid management, use increased generation from renewable energy resources and reduce fueling costs.
The state also will provide EV rebates to Virginians in households living below 300% of the federal poverty line ($26,500 for a family of four) — if it can find the funding (HB 1979).
Qualified residents who purchase or lease new EVs of $55,000 or less will be eligible for a $2,500 rebate and a $2,000 “enhanced rebate.” Purchasers of used EVs of $25,000 or less will be eligible for the $2,500 rebate and an additional $500 enhanced rebate. The rebates will begin Jan. 1, 2022, and expire Jan. 1, 2027. The sticker price is expected to be $13 million in fiscal 2022, rising to almost $70 million in FY 2026.
But the legislation does not include a funding source.
The governor also signed HB 2118, a law that will provide grants on a competitive basis to replace diesel school buses with electric ones. But like the EV rebate law, the bill includes no funding source. The Department of Environmental Quality will be tasked with creating the program “as federal or other nongeneral funding becomes available.”
In SB 1284, the legislature replaced its existing energy policy with the Commonwealth Clean Energy Policy, which calls for addressing climate change, environmental justice and prioritizing economic competitiveness and workforce development.
The policy provides guidance to state agencies and political subdivisions in taking discretionary action on energy issues.
“This bill doesn’t have a lot in the form of teeth, but what it does … is it sets out a number of goals and policy statements related to clean, renewable energy and greenhouse emissions,” Williams Mullen attorney Patrick Cushing said during a legislative briefing last week. If Democrats remain in power, the policy will be a good roadmap for renewable energy policies for the next several years, he added.
Renewables on Brownfields, Former Mines
HB 1925 would create a grant program to locate renewable energy projects on brownfields or coal-mined lands, but the program is dependent on federal funds. The law is a “shell that’s been put in place. It’s not going to receive any state funding,” Cushing said. “It’s there to accept federal funding if it comes down.”
If federal funds become available, funding would be limited to $35 million annually, with grants of $500/kW of nameplate capacity on former mines and $100/kW on brownfields. The law also limits funding to $10 million for a single project on any previously coal-mined land and $5 million for any single brownfield project. Additionally, the law directs the Department of Mines, Minerals and Energy (DMME) to work with stakeholders to develop a handbook for renewable energy and storage development on such projects. (A separate bill which Northam is expected to sign, HB 1855, would change the name of the department to the Department of Energy, effective Oct. 1.)
Northam proposed changes to HB 1899/SB 1252, which would end the Coal Employment and Production Incentive Tax Credit and Coalfield Employment Enhancement Tax Credit after tax year 2021. As written, the bills direct DMME to work with stakeholders to produce a report by Dec. 1 on how the state can provide economic transition support to the coalfield region. Northam said the anticipated savings should be dedicated to the University of Virginia’s College at Wise in Southwest Virginia to expand course offerings in data science, computer science and renewable energy.
GHG Accounting
Also approved during the session was a bill directing the DEQ to start a comprehensive accounting of greenhouse gas emissions, which the state is required to do as a member of the Regional Greenhouse Gas Initiative (SB 1282).
Prior to the signing, Virginia had a hodgepodge of a system for measuring greenhouse emissions, said Lena Lewis, energy and climate policy manager of The Nature Conservancy’s Virginia chapter. Under a more detailed DEQ inventory, she said, emissions such as hydrofluorocarbons (HFCs), will be measured more accurately. HFCs are powerful manmade GHGs that build up in the atmosphere and persist for 15 to 29 years. They are used mainly in refrigeration, air conditioning, insulating foams and aerosol propellants.
It requires the inventory be published and included in an annual report to the State Air Pollution Control Board.
Before Northam’s signature, state officials had few avenues to measure data on carbon and methane emissions from power plants and other large sources of air pollution, mainly state and federal air permits. Officials also depend on widely accepted models to estimate emissions linked to farming and transportation. What DEQ officials did not have was comprehensive data from smaller industrial polluters and infrastructure that relies on natural gas and oil instead of electricity.
An impetus for the bill was an ad hoc work group created in 2019 to develop a framework for limiting methane leakage from natural gas infrastructure. The group found current efforts to measure the leakage are not accurate.
“If we can count emissions levels, we can improve climate outcomes, but we won’t know if we don’t have reliable data,” Lewis said.
Testifying before lawmakers, Chris Bast, DEQ deputy director, said having additional data is key to fighting carbon emissions. “Good policy requires good data, and this legislation gives us the ability to get the data we need to craft good policy going forward.”
Nate Benforado, an attorney with the Southern Environmental Law Center, described the law as “smart, common sense.”
Energy Storage
The legislature also expanded the state’s “permit by rule” policy by amending the definition of “small renewable energy projects” to include storage and hybrid solar-storage facilities (HB 2148). Permit by rule allows solar facilities of 150 MW or less to construct and operate the project through an expedited DEQ permitting process, rather than obtaining approval from the SCC. The DEQ is required to implement the law by Jan. 1, 2022.
New Jersey environmentalists are urging state authorities to move faster to replace existing diesel buses with electric ones, as the state’s mass transportation agency, NJ Transit, embarks on a pilot program that will be its first electric bus initiative.
The state would reap extensive health benefits and remove “significant environmental and public health costs” by accelerating the switch of its 2,183 diesel buses to electric, according to a report released last week by New Jersey Policy Perspective, a nonprofit think tank.
“Electrifying public buses also provides a reliable and cost-effective option to maintain and expand the state’s transit system through advances in electric bus technology and rapid declines in battery costs,” the report says.
The assessment follows a report last month co-produced by Environment New Jersey, an environmental advocacy group, that urged governments across the U.S. to immediately phase out diesel school buses. Although it would come with a hefty upfront price tag, transitioning school fleets to electric buses would save schools money over the lifetime of the bus, according to the report, which was produced with NJPIRG, a public interest advocacy group.
| Shutterstock
The report said that although the $312,000 price of a new electric bus is close to three times as much as a new diesel bus, the lower fuel and maintenance costs for an electric vehicle would mean that the district would save between $80,000 and $130,000 over the 16-year life of each school bus.
The two reports come as NJ Transit lays the ground work for a pilot program in Camden to assess the benefits and challenges of electric buses used in a public service setting. The agency is looking to buy eight battery-powered buses with $8 million awarded by Gov. Phil Murphy from the state’s Volkswagen settlement. In September, NJ Transit awarded a $3.235 million contract for a renovation of Camden’s Newton Avenue Bus Garage that will include EV charging stations and other associated infrastructure modifications. The target for completion is this summer.
In response to the report, NJ Transit says it has placed a priority on investing in environmentally friendly technology. The agency says its five-year capital plan “is geared towards getting to the 2032 goal of 100% of new bus purchases being zero-emission vehicles.” Included in the plan is $300 million for electric buses, spokesman Jim Smith said.
Yet environmentalists question whether the agency is moving fast enough.
“The pilot is a good place to start,” said Doug O’Malley, state director of Environment New Jersey. “But we need continual investment in electric buses by NJ Transit.”
One way to fund the purchase of electric buses and infrastructure would be for utilities to help finance the upfront costs of bus purchases and charging infrastructure installation, with the expenditures repaid through the purchaser’s utility bill, the organization’s report suggests.
O’Malley added that the New Jersey Board of Public Utilities is expected this year to offer a proposal on how best to stimulate the creation of heavy-duty charging stations, which can be used by buses.
The New Jersey Policy Perspective report is skeptical that NJ Transit is on track to meet its 2032 goal. It says that the agency’s capital plan, released in June 2020, contained a timeline that is “misaligned” with the goals set out by the New Jersey legislature. The plan wouldn’t enable NJ Transit to exclusively buy electric buses until 2040, the report says.
In addition, while NJ Transit estimates that the transition to a fully electric fleet will cost $5.7 billion, the report says there is “no clear funding source” in the agency’s capital budget to pay for that change.
That figure is high because the upfront costs are high, according to the report. It puts the cost of replacing the current diesel fleet at $1.96 billion, in large part because the price tag for a 40-foot electric bus with 450 kWh batteries is $749,000, well above the $553,000 for a similarly sized diesel bus.
However, the cost of electric buses is falling, and the cost of batteries for the buses is dropping by about 5 to 10% per year, the report says. NJ Transit could save $81,500 per bus per year by using electric buses because of the removal of mechanical service, oil and filter changes needed on internal combustion engines, as well as fewer tire and brake pad replacements.
A new survey from the American Council for an Energy-Efficient Economy finds that only six states currently have policies encouraging or requiring equity and environmental justice considerations to be built into new programs for rolling out electric vehicle chargers.
According to the report, since 2012, utility commissions in 25 states and D.C. have approved almost $2.4 billion to accelerate the electrification of transportation by putting a total of 200,000 charging stations in cities and along highways. Almost all the approved programs include some provisions aimed at ensuring chargers get into low- and moderate-income (LMI) communities, but carve-outs and other programs for these underserved neighborhoods may only total about $646 million, most of which is being spent in California and New York, the report says.
In other words, said Peter Huether, senior research analyst for transportation at ACEEE and the report’s author, a lot more work needs to be done. He says ensuring equity is incorporated into EV infrastructure planning and programs is critical “because investments in charging infrastructure will shape communities’ transportation options for decades to come.”
But making equity a central focus requires a change in thinking about what residents in LMI neighborhoods actually want and ensuring their active involvement in program design and development, Huether said.
“There’s been a shift in the whole climate-energy space, toward thinking more holistically about things, about equity and putting equity first,” Huether said. “It’s not just light duty vehicle-focused; it’s taking a very public view, looking at the whole system.”
For example, offering rebates for EVs and chargers may not be the most effective way to build interest and support for transportation electrification in low-income communities, the report says, because most residents in these areas do not have access to “charging-capable parking” — dedicated parking spaces with outlets within 20 feet.
Rather, the report suggests that utilities, regulators and local governments first work on electrifying public transportation and ride-sharing services that are often the primary modes of transportation in LMI neighborhoods. Los Angeles launched an EV car-sharing service, BlueLA, in low-income communities in 2018, and the service continues to expand. Low-income residents can enroll for as little as $1/month and get a 25% discount on rental fees.
| Shutterstock
With the health impacts of air pollution a major concern in LMI communities, electrification of heavy- and medium-duty trucking may also be a priority. LMI communities are often located near major sources of carbon emissions and other pollution — sea and airports, refineries and power plants, and highways and other trucking routes — and as a result have higher rates of heart disease and asthma.
The issue became a major driver for Puget Sound Energy when it started talking about potential EV pilot programs with community organizations in its service territory.
“Our initial assumption was that all of our pilots would be focused on light-duty vehicles,” said Mackenzie Martin, community projects manager at PSE. “We heard overwhelmingly from the community that they’d love to explore medium- to heavy-duty pilots as well.”
The utility is now rolling out several pilots aimed at electrifying medium-duty vehicles for tribal transportation services and the fleets of home weatherization companies. In some instances, chargers are being installed where the fleet is based; in others, at a public spot where drivers can pull in and charge up during a lunch break, Martin said.
‘Don’t be Afraid to Slow Down’
Utilities’ efforts at community engagement fall along a continuum from essentially ignoring and marginalizing local voices, to fostering full participation in planning and decision-making, the report says. To some extent, this uneven performance may be attributed to the risk-averse nature of utilities and the ongoing inability of both utilities and regulators to keep up with the pace of adoption of new technologies like EVs.
Surveying 61 utility filings on EV program plans, ACEEE found almost half had no plans for actively engaging LMI communities in program development. About a third included public meetings — a relatively low level of community engagement — while only eight had committed to doing a full community needs assessment, and 10 said they would provide training and advice.
The report points to guidelines for community involvement developed by the nonprofit Greenlining Institute, which puts a strong emphasis on “capacity building” to ensure LMI residents and organizations have the resources and skills needed to fully participate in stakeholder proceedings.
“The reality is that so many communities barely have the capacity to conduct their own scopes of work, let alone to participate in some kind of community engagement or public participation process to figure out where should electric vehicle chargers be installed,” said Hana Creger, the group’s senior program manager for climate equity. “We have to build the capacity of communities to participate in those processes, whether that’s contracting with community-based organizations to conduct outreach or paying residents to participate in those processes. Every single program needs to build in technical assistance.”
In the case of PSE, the community engagement process significantly extended the development and planning process for the utility’s pilot programs, from an initial filing in 2018 to the first project rollouts beginning this year, Martin said.
Her advice to others: “Don’t be afraid to slow down and really look for and ask for that community feedback. Had we not slowed down, I don’t think we would have learned as much as we did, both about the needs of the community but also how to address potential barriers they face.”
Looking Beyond Income
President Biden’s massive infrastructure plan includes $174 billion to put more Americans of all economic classes in American-made EVs, which they will be able to charge on the plan’s proposed national network of 500,000 EV chargers to be installed by 2030. While the plan calls for 40% of all investments to benefit low-income and disadvantaged communities, how money is allocated and to what programs will likely be questions with continuously evolving answers.
To begin with, as the ACEEE report points out, official definitions of LMI, disadvantaged and environmental justice communities vary widely between states, affecting which communities get help and the level of funding and services they receive.
Looking beyond income, “these decisions should be informed by both input from communities and overarching state equity, air quality, climate and mobility goals,” the report says. “Adding criteria around race, tribal status or pollution burden to income requirements … would allow programs to better target the neediest individuals and rectify some wrongs in current transportation systems.”
Equity carveouts are only a first step and should be tracked and monitored to ensure they have the desired impacts across multiple benchmarks, Creger said. “Every single electric vehicle charging infrastructure should be kind of a lifeline to creating high-quality jobs and opportunities,” she said. “It’s not enough to assume that these benefits will trickle down to communities. We really have to target them,” she said.
ACEEE analyzed the data collected and tracked for the EV programs of 12 utilities, and again found uneven performance. Seven were tracking engagement with LMI communities, while only three were tracking the number of chargers installed in these neighborhoods. Only one utility was tracking the percentage of chargers installed and the number of applications and amount of rebates paid in LMI communities.
Creger now believes upfront incentives to spur EV sales should be limited to those that target the LMI market. Incentives that spurred sales among early and mostly well-off adopters were “OK 10 years ago when they were trying to get the market off the ground, but it’s 2021 now; the market is officially off the ground.”
“We need to begin to reform and retire those clean vehicle incentives, and the ones that we do actually retain have to be specifically targeted to low-income people,” Creger said. “We have programs that do that really well; they are just very underfunded and have really long wait lists.”
In case you missed the headlines, Berkshire Hathaway Energy wants to give Texas 10 GW of new emergency generation to be fueled by liquefied natural gas, at a cost of $8.3 billion, in exchange for a guaranteed return on that $8.3 billion. Got it?
BH bills this as a “TOTAL SOLUTION” to the tragedy this winter in Texas.
Spearing Fish in the Barrel
Let’s look at this tragedy with the ERCOT data in this graphic.[1] Looking at the load shed line you can see that from about 5 a.m. on Feb. 15 to about 8 p.m. on Feb. 17, BH’s 10 GW would not have alleviated load shed. So the energy price in ERCOT would have been $9,000/MWh for those 63 hours at a cost of $28.35 billion.[2] How is that a “TOTAL SOLUTION?” Or any solution?
Wait, there’s more. BH’s slide deck claims that its $8.3 billion proposal has a “Lifetime Cost of Solution” of $3.55 billion. How can a project costing $8.3 billion have a lifetime cost of $3.55 billion?
Berkshire Hathaway Energy’s proposal to supply 10 GW of emergency generation to ERCOT would not have been enough to prevent load shedding on Feb. 15-18, when unserved load approached 20 GW. (See area shaded gray.) | ERCOT
Another of my favorites: BH says it will provide “a $4 billion performance guarantee.” Hmm. Let’s say I give you $8.3 billion for an insurance package and if you fail to meet your obligation you give me $4 billion. Such a deal.
BH claims that its proposal costs less than winterizing existing assets. But think about that. The BH assets presumably would need to be winterized — otherwise what are we doing here? Would the incremental winterizing cost for 10 GW of existing facilities cost many billions more than the incremental winterizing cost for 10 GW of new facilities? If not, why spend $8.3 billion on new facilities?
Let’s take an example of South Texas Nuclear Unit 1, which tripped off the early morning of Feb. 15 and didn’t start to return to service until late Feb. 17. The cause of the outage was reported to be freezing of a pressure sensor line that caused water pumps to trip.[3] Winterizing such equipment, as is done elsewhere, would have cost a pittance and would have provided equivalent capacity value to 1.3 GW of BH’s proposal — for which BH proposes to charge $1.1 billion.[4]
The South Texas nuclear plant suffered an outage from Feb. 15 to 17 because of a frozen pressure sensor line, which caused water pumps to trip. | NRG
Low-hanging Fruit
Texas should pick some low-hanging fruit before ever throwing $8.3 billion at BH. Some modest proposals:
Make sure electric utilities don’t curtail critical gas infrastructure.[5]
Don’t allow maintenance outages during the peak winter season.
Make utility curtailment more granular so that empty office buildings aren’t blazing because there’s a fire station on the same distribution circuit.
Use effective, broad communication to customers, like the Emergency Broadcast System, to request voluntary conservation and to let customers know what to expect.[6]
Require appropriate winterization of gas and electric facilities. I gave above the example of South Texas Nuclear Unit 1 tripping, which cost NRG, operator and 44% owner of the plant, about $374 million of foregone revenue.[7] But somehow that kind of money wasn’t sufficient incentive for NRG to winterize such equipment. Perhaps that’s because foregone revenue doesn’t appear in financial reporting.[8] But whatever the explanation, this can’t be allowed to happen again.
Where dual-fuel capability (like diesel or LNG) makes sense, add it to existing generation. That saves the entire cost of new generation. If Texas decides it wants to fund, say, 10 GW of that, it could have generators bid in a descending clock auction to add it. Not rocket science.[9]
Again, I wish the best to Texas in recovering from this tragedy and in avoiding another one.
[7] NRG owns 44% of Unit 1, so the math on foregone revenue is the unit’s 1,312 MW times 44% times $9,000/MWh times the 72 hours the unit was out.
[8] Interestingly, NRG has had two Wall Street conference calls since the tragedy and got exactly zero questions about the nuclear plant outage and the foregone revenue involved.
The debate over using large-scale blackouts to prevent wildfires in California has become more urgent as the state heads into another fire season after a dry winter, with some urging restraint and others recommending more public safety power shutoffs (PSPS).
Federal Judge William Alsup, who oversees Pacific Gas and Electric’s criminal probation from the 2010 San Bruno gas explosion, is weighing new probation conditions that would require PG&E to expand its criteria for de-energizing lines when nearby trees pose a threat.
The state’s largest utility was blamed for catastrophic wildfires from 2017 to 2020 caused by its equipment contacting vegetation. The blazes include last year’s Zogg Fire, which began when a leaning gray pine tree struck a PG&E transmission line, the California Department of Forestry and Fire Protection concluded in March. (See PG&E Equipment Started Zogg Fire, Investigation Finds.) The fire killed four residents of Shasta County and burned 56,000 acres.
The Zogg Fire prompted Alsup’s proposed probation conditions, requiring the utility to consider hazard trees, like the gray pine, outside its usual clearance zone when determining which lines to shut down in high winds.
An analysis by wildfire firm Technosylva showed the spread of a potential fire if PG&E had not de-energized its lines in October 2019. | Technosylva
The California Public Utilities Commission has opposed Alsup’s proposal, arguing it could double the number of PSPS events and put residents and emergency responders in jeopardy.
“The potential doubling of public safety power shutoff events in PG&E’s service territory under these modified proposed conditions could translate into a corresponding or even greater increase in the public safety perils flowing directly from the use of PSPS,” the CPUC said in a March 19 letter to Alsup.
“PSPS is a vital wildfire prevention and mitigation tool that electric utilities can use, but PSPS itself raises serious public safety consequences by potentially impairing emergency services, water pumping capability and communications infrastructure,” the commission said in a subsequent court filing on March 29.
The CPUC urged Alsup to let it handle PSPS oversight, saying it is already “years into an ongoing and iterative public process — through several formal proceedings and informal processes — of improving PSPS as a tool of last resort, while mitigating the safety hazards that flow directly from the use of PSPS.”
Effectiveness Versus Harm
In a hearing last week, the CPUC focused on the harmful impacts of PSPS on disabled residents and those with medical needs. Shutting off power to customers who rely on electrical equipment is a major concern for commissioners, who have criticized the slowness of PG&E and Southern California Edison (SCE), the state’s second largest utility, to supply battery backup power to vulnerable residents. (See PG&E Working to Improve Safety Blackouts.)
A recent study commissioned by the CPUC, however, found that devastating fires could have occurred without PSPS.
The study by wildfire consulting firm Technosylva concluded that PG&E’s controversial power shutoffs in 2019 may have prevented the burning of more than 3.4 million acres and nearly 283,000 structures. High winds caused hundreds of damage incidents on the utility’s lines that may have sparked fires, including one massive conflagration of more than 3 million acres, Technosylva said. The analysis considered weather and fuel conditions, among other factors.
PG&E’s PSPS events in October 2019 left 2.4 million residents in the dark and led to public outrage and harsh criticism from lawmakers and the CPUC. (See California Officials Hammer PG&E over Power Shutoffs.)
Public anger over PSPS rose again last year when PG&E and SCE made unprecedented use of power shutoffs, blacking out residents through the holidays and into January. CPUC President Marybel Batjer said SCE’s failure to notify customers that a PSPS would be activated on Thanksgiving morning was especially egregious because it disrupted family gatherings.
During a hearing in early March, Assembly Utilities and Energy Committee Chair Chris Holden said PSPS was used 30 times between 2013 and 2019.
“It’s safe to say that we’re all frustrated by the use of public safety power shutoffs by our state’s electric utilities,” Holden said.
Anger over intentional blackouts is expected to play a role in the likely recall election of Gov. Gavin Newsom this fall, during the height of fire season. Proponents of the recall say they have gathered sufficient signatures, though the results have not been certified yet. Newsom’s handling of the COVID pandemic is at the heart of the recall effort.
The New Jersey Board of Public Utilities (BPU) is studying whether sending two separate bills or one “consolidated” bill to community solar subscribers is the most effective and user-friendly way to attract and keep customers signed on to projects in the fast-growing sector.
The state’s first community solar project began operating in January, and three more have since come online, for a combined capacity of 9 MW. With more than 40 projects in the pipeline, the BPU is midway through a public comment process to determine which billing system would work best for utilities, community solar program developers and consumers.
With a two-bill option, consumers receive their regular utility bill, plus a separate bill for their community solar subscription. The other option, a consolidated bill, provides a single accounting, compiled by the utility or energy supplier, that includes the cost of the community solar energy and all other electricity or power costs.
The March 25 hearing on the issue drew a range of stakeholders, including representatives of PSE&G, Atlantic City Electric, solar developers and advocacy groups. Most, but not all, favored a consolidated bill.
“A dual bill is really going to confuse retail customers,” said Jacob Sussman, COO of Evergreen Energy, a community solar project developer, adding that it would be harder to sign up consumers if they were going to receive two bills. “What potentially could happen is that people feel that community solar is a scam. They are going to lose faith in the system.”
Sussman and other speakers believe the BPU’s decision could determine whether community solar projects are successful in New Jersey. Potential subscribers receiving two separate bills would have to calculate the combined total and compare it to past bills to see if they have saved money, they said.
But Jake Springer, senior policy associate for Nexamp, a developer, owner and operator of solar projects, said the idea that consolidated billing is a “panacea” for marketing community solar is wrong. A well-designed consolidated billing system could be viable, but is not the only option, he said.
“Dual billing exists today in other markets that are farther along than New Jersey is right now,” he said.
The BPU is scheduled to release a report on the issue on May 28.
Growing Interest in Community Solar
New Jersey is one of about 20 states that have recognized the benefits of shared renewables by encouraging their growth through policy and programs, according to the Solar Energy Industries Association. Others include Massachusetts, Community Shared Solar Grows in NYC.)
Community solar projects are targeted at consumers — whether homeowners or small businesses — who either cannot or do not want to have solar on their roofs. In many instances, developers start enrolling subscribers before they begin building a project or look for a business to be an “anchor” subscriber by committing to buying a certain percentage of the power from the project.
In return for subscribing, the consumer receives a credit on their utility bill, reducing the electricity cost by a set percentage. The solar project operator then supplies the electricity generated in the project to a utility company, which provides power to the consumer in the same way the utility did before opting into community solar.
New Jersey Governor Phil Murphy is pushing community solar in the state’s effort to reach 100% clean energy by 2050. Murphy wants the state to have 32 GW of solar by then, about nine times the capacity online today.
Community solar also supports Murphy’s commitment to environmental justice and helping low- and moderate-income residents lower their electricity bills. Consumers generally pay little or no money upfront to subscribe to a project and, depending on the developer, can lock in savings of a certain percentage, typically 5% to 20%, on their monthly electric bills. Forty percent of the capacity in the BPU’s community solar program is reserved for low- and moderate-income residents.
Rising Consumer Interest
Shaun Keegan, CEO of Solar Landscape of Asbury Park, which developed the first two community solar projects in New Jersey, said that public interest in the projects is notable.
Located in Perth Amboy, New Jersey’s first community solar project is now 75% subscribed, developer Solar Landscape says. | Solar Landscape
“It doesn’t cost anything to enroll. You can cancel at any time,” he said, adding that he believes the sector is growing steadily. “It checks all the boxes, triple bottom line: People. Planet. Profit.”
In 2019, the BPU approved 45 community solar projects totaling 78 MW. The Solar Landscape projects, on the rooftops of two Perth Amboy warehouses, began operating in January, and two smaller projects have since come online in Secaucus and Pennsauken. The BPU is considering proposals for a second phase of solar community projects, which together will generate 150 MW of electricity.
Lawrence Garb, executive vice president of Hartz Mountain Industries, which developed the Secaucus community solar project, said the company will have three more community solar projects online by the end of April, generating about 6.5 MW. Garb said the company, which mainly manages real estate, has been installing solar on company warehouses for more than a decade. But state regulations allowed the electricity from those projects to be used only in the buildings, while the community solar energy can be sold to the public.
Solar Landscape had about half the project target of 1,200 subscribers signed up when it launched the Perth Amboy projects, Keegan said. Now, the projects, which give participants a 10 to 20% savings on their bill, is about 75% subscribed, he said.
Solar Landscape uses a two-bill system but favors consolidated billing, as does Hartz Mountain, and several other developers.
Hartz Mountain Industries developed this community solar project now online in Secaucus and is planning three more. | Hartz Mountain Industries
“Having to explain to a customer that they will get two bills is definitely the biggest bottleneck,” said Nicholas Minekime, managing director of solar developer Altus Power America, “People already have enough difficulty understanding how community solar works in the first place.”
A Deeper Connection
Community solar subscribers in Massachusetts and Minnesota, states with established community solar markets, receive two bills, said Allan Telio, senior vice-president for Nexamp, a developer with projects in several states. The key to success in dual billing is to ensure transparency and understandability in both bills so that consumers can easily see what they are paying for and getting in return, he said.
A separate bill for the cost of the community solar can even make consumers feel more involved with the clean energy project, he said. “From a psychological perspective there’s a deeper connection,” he said.
If New Jersey were to opt for consolidated billing, many details would have to be worked out. The BPU is gathering information on topics including stakeholders’ experience of consolidated billing in other states and the potential challenges facing a consolidated billing system implemented in New Jersey.
In New York, the state Public Service Commission requires community solar projects that participate in its program to use a consolidated system, with subscribers given a credit on their utility bills, said Kristen Barone of Orange and Rockland Utilities. Subscribers are guaranteed at least 5 percent savings on their electricity bills, and the utility takes an administration fee for compiling the consolidated bill, she said.
Steve Sunderhauf from the Atlantic City Electric Company, said consolidated billing would provide consumers with a single electric bill that would include distribution, transmission and generation charges, all surcharges on taxes and all other items currently on utility bills. Its success could depend on acceptance by solar developers and consumers and a clear framework as to how the cost of developing the consolidated system would be recovered, he said.
Randi Orlow, solar program director for Neighborhood Sun Benefit Corp, a subscriber organization, said the group favors a consolidated bill; clarity and transparency are key.
“We want the subscriber to be able to easily identify who their community solar provider is, exactly what the charges are, what the discount is, and who they should reach out to if a concern needs resolution,” she said.
